Oil Producers in Midland Are Working on the Next Permian
Permian producers are looking for new places and ways to sustain production in the giant basin.
Generations of wells cover the Permian, and a new wave is expected.
Source: Stephen Rassenfoss
When the title of the keynote address at an oil conference in Midland is “The Secret To Finding the Next Permian,” it suggests there are people with doubts about the status quo.
Unconventional oil production there has been around 5.7 million B/D this year, and the video board at a downtown bank was showing the drop in the Permian rig count this year as prices have risen to nearly $100/bbl.
Speakers at the recent SPE Permian Basin Energy Conference were optimistically focused on the changes needed to sustain that high output and high profit margins as well.
The inventory of the most productive, Tier 1 drilling sites is dwindling for the benches that have delivered much of the production in recent years, said Dave Cannon, senior vice president of geoscience and technology for Diamondback Energy. He asked, “What is the next Tier 1 out there 10 years from now?”
When it came time for the keynote speaker to describe the next Permian, Clay Gaspar, executive vice president and chief operating officer for Devon Energy, said, “We are standing on it now.”
The oil- and gas-rich rock is there but avoiding a repeat of the 50-year slump that preceded the shale boom over the past decade will require a combination of incremental improvements in finding, developing, and producing oil, as well developing new zones as intense development crimps production of new wells in the Wolfcamp and Spraberry formations.
Producers are working on ways to maximize well productivity in what is left in those layers, which is considerable.
ConocoPhillips reported on a massive development where it is now drilling 44 wells, from pads lined up at the narrow ends of the 2×3-mile-long site. Soon, when the five rigs near the end of the drilling jobs, fracturing will begin.
The high well count, which is needed to satisfy lease obligations, is also a test of whether they can maximize production when all wells start up at the same time,
If it works as planned, none of the wells will have their production reduced by an older well nearby. And unlike past experiences with megapads, which delivered disappointing results, the spacing isn’t compressed compared to normal sized pads.
This is also a test site for new methods such as electric-powered drilling and the processing of field gas on site so that it can be used to power fracturing.
This isn’t the only large-sized block left for ConocoPhillips but having that much space to work has become a limited commodity.
Infill drilling has become the norm, and as has always been the case; new wells added near older parent wells are not as productive.
A study by Goehring & Rozencwajg Natural Resource Investors predicted that Permian production would peak soon, due in large part to the high level of infill drilling.
“In 2012 we estimate that only 30% of wells drilled in the three significant shale basins were ‘children.’ By 2022, that figure had reached 85%. In Tier 1 areas, effectively, all current wells are children, with lower-than-expected productivity,” the consultant’s report said.
The Permian’s vital signs are tracked on a sign outside a bank in downtown Midland.
Source: Stephen Rassenfoss
Solving Puzzles
Other sources, including Enverus and the US Geological Survey, offer much higher estimates of the remaining drillable acreage, but the big companies there talked about the efforts to find new productive horizons. They have some ideas, but at this point there are puzzles to solve.
“Some of the resources we will develop in the future are not considered a resource now based on current methods,” Gasper said.
Some of what’s new will be flowing out of old wells using new methods, such as refracturing old wells in the Permian and exploring new horizons such as the upper Spraberry and the Barnett Shale.
In both those plays good wells have been drilled. Cannon said they “are starting to catch fire.” But at this early stage, it is a bit like lighting wet wood.
“The Upper Spraberry is being tested. It is dramatically more complex, with a much wider distribution of production results. That is the subsurface talking,” Cannon said.
Elevation Resources has been successfully drilling oil wells in the Barnett in the Central Basin Platform, and Occidental has increased its Barnett testing from two wells in 2021 to 12 in the Midland Basin this year, according to a recent report from Rystad Energy.
That study also pointed out APA Corp.’s Barnett discovery in 2019, which initially looked like a big oil find but proved to be mostly gas. The fact that as Permian oil-producing wells age, they tilt toward all-gas production means that little effort will be required to ensure the next Permian will be a robust gas producer.
A report from Enverus describing productive zones in the basin said the Upper Spraberry is the “least proven” of the Spraberry layers. It said the Barnett is part of a group of three benches that are “structurally complex with a high degree of faulting and erosion.”
Employing new methods for getting more from older wells is also part of the plan.
If massive tax credits are able to create a large supply of CO2 captured from smokestacks and the atmosphere, that could create opportunities to expand enhanced oil recovery. That would earn credits for gas that remained in the ground, but the public’s interest has been on long-term sequestration, which benefits from a larger tax break.
One reason for that is that injecting into fractured ultratight rock has presented more problems than opportunities.
Chevron presented two papers that showed it was able to use gas injection to increase the oil production on multiple wells near an injection well. The gains were not large, but showed a major oil company in the Permian is putting serious resources behind an unconventional EOR option, using huff-n-puff methods well by well.
And there’s potential in wells completed before 2013 that “is literally untouched, sitting behind the pipe,” Cannon said, adding, “We have to invest in new technology to make it effective.”
He and others on the panel used the future tense when talking about refracturing those older wells to go after the rock not stimulated in the Permian.
Devon has shown it is possible to increase yields on badly completed old wells in the Eagle Ford to around 15% from 5%, but not yet in the Permian.
“By year-end we will have 50 refracs in the ground, with several 100 more on the drawing board” Gaspar said. But he cautioned that this is limited to older wells with wide cluster spacing—60 ft for example—in relatively good condition.
While they are evaluating more than 500 wells, many will not make the cut. Those that do will be “without mechanical issues” that can interfere with running a liner to cover old perforations or problems that could limit their ability to safely pump the job.
So far, refracturing testing has been done in the Eagle Ford where acreage in oil-producing zones has largely been drilled out. Reasons offered for not doing the same range from fear of the unknown to a lack of data showing refracs as a competitive option to new well development in the Permian where acreage remains available.
Even with all those ideas and more, it will be difficult for new wells to keep up with rapidly declining older wells, but nobody at the conference said they doubted the Permian has another life left in it.
Nick McKenna, vice president of Midland Basin for ConocoPhillips, explained that confidence: “Never bet against innovation.”
